U.S. patent application number 12/787247 was filed with the patent office on 2011-12-01 for system for fuel and diluent control.
This patent application is currently assigned to GENERAL ELECTRIC COMPANY. Invention is credited to Brett Matthew Thompson.
Application Number | 20110289932 12/787247 |
Document ID | / |
Family ID | 44352249 |
Filed Date | 2011-12-01 |
United States Patent
Application |
20110289932 |
Kind Code |
A1 |
Thompson; Brett Matthew |
December 1, 2011 |
SYSTEM FOR FUEL AND DILUENT CONTROL
Abstract
According to various embodiments, a system includes a fuel
controller configured to control a fuel transition between a first
flow of a first fuel and a second flow of a second fuel into a fuel
nozzle of a combustion system. The fuel controller is configured to
adjust a third flow of a diluent in combination with the second
flow of the second fuel to maintain a pressure ratio across the
fuel nozzle above a predetermined operating pressure ratio.
Inventors: |
Thompson; Brett Matthew;
(Simpsonville, SC) |
Assignee: |
GENERAL ELECTRIC COMPANY
Schenectady
NY
|
Family ID: |
44352249 |
Appl. No.: |
12/787247 |
Filed: |
May 25, 2010 |
Current U.S.
Class: |
60/776 ;
60/778 |
Current CPC
Class: |
F05D 2270/16 20130101;
Y02E 20/16 20130101; Y02E 20/18 20130101; F02C 3/30 20130101; F05D
2220/75 20130101; F02C 9/40 20130101 |
Class at
Publication: |
60/776 ;
60/778 |
International
Class: |
F02C 7/26 20060101
F02C007/26 |
Claims
1. A system, comprising: a fuel controller configured to control a
fuel transition between a first flow of a first fuel and a second
flow of a second fuel into a fuel nozzle of a combustion system,
wherein the fuel controller is configured to adjust a third flow of
a diluent in combination with the second flow of the second fuel to
maintain a pressure ratio across the fuel nozzle above a
predetermined operating pressure ratio.
2. The system of claim 1, wherein the fuel controller is configured
to control the pressure ratio across the fuel nozzle via adjustment
of the third flow of the diluent to prevent flashback or flame
holding.
3. The system of claim 1, wherein the fuel controller is configured
to increase the third flow of the diluent and decrease the second
flow of the second fuel to enable operation of the combustion
system at a lower load.
4. The system of claim 3, wherein the fuel controller is configured
to increase the third flow of the diluent and decrease the second
flow of the second fuel while at least one gasifier of a plurality
of gasifiers is offline.
5. The system of claim 1, wherein the fuel controller is configured
to control the fuel transition during startup or shutdown of the
combustion system.
6. The system of claim 1, wherein the fuel controller is configured
to control the fuel transition in response to feedback indicative
of at least one of a pressure, a temperature, a heating value, a
flow rate, a speed, a load, or a combination thereof.
7. The system of claim 1, wherein the diluent comprises at least
one of nitrogen, steam, or a combination thereof.
8. The system of claim 1, wherein the first fuel comprises at least
one of natural gas, distillate, liquefied petroleum gas, or a
combination thereof and the second fuel comprises syngas.
9. The system of claim 1, comprising the combustion system having
the fuel nozzle disposed in a combustor of a gas turbine
engine.
10. A system, comprising: a fuel controller is configured to
control a pressure ratio across a fuel nozzle in a combustion
system to prevent flashback or flame holding, wherein the fuel
controller is configured to adjust a first flow of a diluent in
combination with a second flow of a fuel to maintain the pressure
ratio above a predetermined operating pressure ratio.
11. The system of claim 10, wherein the fuel controller is
configured to control a fuel transition between the second flow of
the fuel and a third flow of another fuel into the fuel nozzle,
wherein the fuel controller is configured to adjust the first flow
of the diluent in combination with the second flow of the fuel to
maintain the pressure ratio above the predetermined operating
pressure ratio during the fuel transition.
12. The system of claim 10, wherein the fuel controller is
configured to obtain feedback indicative of a flow rate of the
first flow of the diluent, wherein the fuel controller is
configured to maintain the flow rate of the diluent above a diluent
flow rate setpoint.
13. The system of claim 10, wherein the fuel controller is
configured to obtain feedback indicative of a heating value of a
mixture of the first flow of the diluent and the second flow of the
fuel, wherein the fuel controller is configured to maintain the
heating value of the mixture above a heating value setpoint.
14. The system of claim 10, wherein the fuel controller is
configured to increase the first flow of the diluent and decrease
the second flow of the fuel to enable operation of the combustion
system at a lower load.
15. The system of claim 10, wherein the fuel comprises syngas, and
the diluent comprises a non-combustible gas or vapor.
16. The system of claim 10, comprising the combustion system having
the fuel nozzle disposed in a combustor of a gas turbine
engine.
17. A system, comprising: a fuel controller configured to adjust a
first flow of a diluent in combination with a second flow of a fuel
to maintain a pressure ratio across a fuel nozzle above a
predetermined operating pressure ratio, wherein the fuel controller
is configured to increase the first flow of the diluent and
decrease the second flow of the fuel to enable operation of a
combustion engine at a lower load.
18. The system of claim 17, wherein the fuel controller is
configured to control a fuel transition between the second flow of
the fuel and a third flow of another fuel into the fuel nozzle,
wherein the fuel controller is configured to adjust the first flow
of the diluent in combination with the second flow of the fuel to
maintain the pressure ratio above the predetermined operating
pressure ratio during the fuel transition.
19. The system of claim 17, wherein the fuel controller is
configured to increase the first flow of the diluent and decrease
the second flow of the fuel while at least one gasifier of a
plurality of gasifiers is offline.
20. The system of claim 17, wherein the fuel controller is
configured to obtain feedback indicative of an operational
parameter of the combustion system, wherein the fuel controller is
configured to adjust the first flow of the diluent to maintain the
operational parameter within a range of a setpoint to maintain the
pressure ratio above the predetermined operating pressure ratio.
Description
BACKGROUND OF THE INVENTION
[0001] The subject matter disclosed herein relates to flow control
systems and, more particularly, to systems for fuel and diluent
flow control.
[0002] A variety of combustion systems burn a fuel to create
energy. For example, an integrated gasification combined cycle
(IGCC) power plant includes one or more gas turbine engines that
burn a fuel to create energy that powers a load. One of the fuels
used by the gas turbine engine may be syngas produced by one or
more gasifiers of the IGCC power plant. Operation of the gas
turbine engine may require a minimum fuel nozzle pressure ratio to
avoid flame holding, flashback, or other problems. As a result, the
gas turbine engine may be incapable of operating below a minimum
load for certain fuels, such as syngas. For example, during
startup, the gas turbine engine may operate using natural gas up to
the minimum load, and then transition to operation using the
syngas. This operational limit reduces the efficiency of the gas
turbine engine and the IGCC power plant.
BRIEF DESCRIPTION OF THE INVENTION
[0003] Certain embodiments commensurate in scope with the
originally claimed invention are summarized below. These
embodiments are not intended to limit the scope of the claimed
invention, but rather these embodiments are intended only to
provide a brief summary of possible forms of the invention. Indeed,
the invention may encompass a variety of forms that may be similar
to or different from the embodiments set forth below.
[0004] In a first embodiment, a system includes a fuel controller
configured to control a fuel transition between a first flow of a
first fuel and a second flow of a second fuel into a fuel nozzle of
a combustion system. The fuel controller is configured to adjust a
third flow of a diluent in combination with the second flow of the
second fuel to maintain a pressure ratio across the fuel nozzle
above a predetermined operating pressure ratio.
[0005] In a second embodiment, a fuel controller is configured to
control a pressure ratio across a fuel nozzle in a combustion
system to prevent flashback or flame holding. The fuel controller
is configured to adjust a first flow of a diluent in combination
with a second flow of a fuel to maintain the pressure ratio above a
predetermined operating pressure ratio.
[0006] In a third embodiment, a system includes a fuel controller
configured to adjust a first flow of a diluent in combination with
a second flow of a fuel to maintain a pressure ratio across a fuel
nozzle above a predetermined operating pressure ratio. The fuel
controller is configured to increase the first flow of the diluent
and decrease the second flow of the fuel to enable operation of a
combustion engine at a lower load.
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] These and other features, aspects, and advantages of the
present invention will become better understood when the following
detailed description is read with reference to the accompanying
drawings in which like characters represent like parts throughout
the drawings, wherein:
[0008] FIG. 1 is a block diagram of an embodiment of an IGCC power
plant incorporating a gas turbine engine with a fuel control system
configured to expand an operational range of the gas turbine
engine;
[0009] FIG. 2 is a block diagram of a gas turbine engine
incorporating an embodiment of a fuel control system configured to
expand an operational range of the gas turbine engine;
[0010] FIG. 3 is a graph of an operating envelope for a gas turbine
engine according to an embodiment;
[0011] FIG. 4 is a block diagram of an embodiment of a fuel control
system configured to expand an operational range of the gas turbine
engine;
[0012] FIG. 5 is a block diagram of an embodiment of a fuel control
system using schedule-based control;
[0013] FIG. 6 is a block diagram of an embodiment of a fuel control
system using a transfer function for closed-loop control; and
[0014] FIG. 7 is a block diagram of an embodiment of a fuel control
system using a model for closed-loop control.
DETAILED DESCRIPTION OF THE INVENTION
[0015] One or more specific embodiments of the present invention
will be described below. In an effort to provide a concise
description of these embodiments, all features of an actual
implementation may not be described in the specification. It should
be appreciated that in the development of any such actual
implementation, as in any engineering or design project, numerous
implementation-specific decisions must be made to achieve the
developers' specific goals, such as compliance with system-related
and business-related constraints, which may vary from one
implementation to another. Moreover, it should be appreciated that
such a development effort might be complex and time consuming, but
would nevertheless be a routine undertaking of design, fabrication,
and manufacture for those of ordinary skill having the benefit of
this disclosure.
[0016] When introducing elements of various embodiments of the
present invention, the articles "a," "an," "the," and "said" are
intended to mean that there are one or more of the elements. The
terms "comprising," "including," and "having" are intended to be
inclusive and mean that there may be additional elements other than
the listed elements.
[0017] As discussed below, the disclosed embodiments increase the
operational range of a gas turbine engine by diluting a fuel to
control a fuel nozzle pressure ratio (FNPR), thereby enabling
operation with the fuel at lower loads. In addition, the disclosed
embodiments are capable of controlling the FNPR across the entire
operating range of the gas turbine engine. The gas turbine engine
may burn one or more different fuels. For example, gas turbine
engines used in IGCC power plants may burn syngas produced by one
or more gasifiers as fuel. However, the availability of syngas may
be affected by startups, shutdowns, unscheduled outages, or routine
maintenance. During such situations, gas turbine engines may use
natural gas instead of syngas or a combination of natural gas and
syngas. When there is a large difference between heating values of
the fuels, as with natural gas and syngas, each fuel may be
directed to a separate fuel nozzle of the combustion system. For
example, in certain embodiments, natural gas may be directed to a
primary nozzle and syngas may be directed to a secondary nozzle.
Because of the difference in design flow rates and heating values
of the fuels, a nozzle area of the primary nozzle may be less than
that of the secondary nozzle. In other embodiments, where the
heating values of two fuels are similar, one fuel nozzle may be
used for both fuels. Devices, such as control valves, may be used
to adjust the flow rates of the fuels and/or fuel mixtures.
[0018] In addition to fuels, a diluent may be directed to a
combustor of the gas turbine engine. In general, diluents may be
include vapors or gases, such as inert gases or non-combustible
gases or vapors. Specific examples of diluents include, but are not
limited to, nitrogen, carbon dioxide, steam, water vapor, or
combinations thereof. As with fuels, the diluent may be directed to
a separate nozzle in the combustor of the gas turbine engine.
Alternatively, the diluent may be mixed with one or more of the
fuels prior to injection into the gas turbine engine. In addition,
a device, such as a control valve, may control the flow rate of the
diluent.
[0019] A fuel control system may send signals to the fuel and
diluent control valves to control the flow rates of the fuels and
diluent to control an operational range of the gas turbine engine.
To determine the flow rates of the fuels and diluent, the
controller may receive signals based on either measured or
calculated parameters. In various embodiments described in detail
below, the fuel control system may receive signals based on the
FNPR, which is defined as the fuel supply pressure divided by the
combustor pressure, e.g., upstream pressure divided by downstream
pressure. In order for fuel to flow into the combustor, the fuel
supply pressure is greater than the combustor pressure, which
results in an FNPR greater than one. Furthermore, operation of the
combustor may be limited to operation between a minimum, or lower
or predetermined operating, FNPR and a maximum, or upper, FNPR.
Operation below the minimum FNPR or above the maximum FNPR may
result in undesirable combustion dynamics, flame holding,
flashback, or other problems. Although the fuel supply pressure may
be measured, the combustor pressure typically is not. Therefore,
the FNPR may not be directly measured, but may be inferred from
other gas turbine engine operating conditions. In various
embodiments described below, examples of gas turbine engine
operating conditions that may be used to infer the FNPR include,
but are not limited to, inlet guide vane (IGV) position, corrected
speed, exhaust temperature, fuel flow rate, fuel lower heating
value (LHV), or combinations thereof. The corrected speed refers to
the speed a component would rotate at if the inlet temperature
corresponded to ambient conditions at sea level.
[0020] A heating value may be used to define energy characteristics
of the fuel. For example, the heating value of the fuel may be
defined as the amount of heat released by combusting a specified
quantity of fuel. In particular, a LHV may be defined as the amount
of heat released by combusting a specified quantity (e.g.,
initially at 25 degrees C. or another reference state) and
returning the temperature of the combustion products to a target
temperature (e.g., 150 degrees C.). LHV may be represented in the
units of Megajoule (MJ) per kilogram (kg). In the following
discussion, LHV may be used to indicate the heating value of
various fuels, but it is not intended to be limiting in any way.
Any other value may be used to characterize the energy and/or heat
output of feedstock within the scope of the disclosed
embodiments.
[0021] In presently contemplated embodiments, the FNPR may be used
by the fuel control system to control the fuel and diluent flow
rates to control an operational range of the gas turbine engine.
For example, the disclosed embodiments control the diluent flow to
maintain the FNPR between the minimum FNPR and the maximum FNPR to
preserve the integrity of the gas turbine engine, while more
specifically maintaining the FNPR above the minimum FNPR to prevent
flashback and flame holding. Above the minimum FNPR, a flame is
maintained at a proper distance away from a tip of the fuel nozzle.
When the distance between the flame and the tip of the fuel nozzle
is small or non-existent, referred to as flame holding, the flame
may damage the tip of the fuel nozzle. In addition, operation above
the minimum FNPR may prevent flashback, e.g. travel of the flame
upstream through the fuel nozzle. Thus, the minimum FNPR may define
one boundary of an operating envelope of the gas turbine engine. In
the disclosed embodiments, the diluent is added to the fuel
specifically to maintain a suitable FNPR, thereby eliminating the
typical operational boundary based on the minimum FNPR associated
with the fuel. In other words, the fuel may be diluted with the
diluent to maintain the minimum FNPR, while allowing the gas
turbine engine to operate with the fuel at a much lower load.
[0022] Thus, according to certain embodiments, the fuel control
system may inject nitrogen, steam, or other diluents into one of
the fuel streams to adjust the FNPR. Specifically, a number of
variables may affect the FNPR, including the fuel ratio (while
operating with multiple fuels) and the flow rate of diluent being
fed to the gas turbine engine. For example, decreasing the ratio of
syngas to natural gas reduces the FNPR and increasing the flow rate
of diluent increases the FNPR. Thus, without the diluent, operating
below a minimum syngas flow rate may cause the FNPR to drop below
the minimum FNPR. For example, the IGCC power plant may include
several gasifiers that supply syngas to the gas turbine engines. If
one or more of the gasifiers shuts down, the total supply of syngas
may be reduced to a level insufficient for one or more of the gas
turbine engines to operate above the minimum FNPR. By increasing
the flow rate of diluent to increase the FNPR, the disclosed
embodiments enable the gas turbine engine to continue to operate
even when one or more of the gasifiers are shut down. In various
embodiments, the diluent may be blended with one of the fuels prior
to injection into the combustor of the gas turbine engine. By
adjusting the flow rate of the diluent, the fuel control system may
maintain operation above the minimum FNPR and thus, effectively
increase the operating range of the gas turbine engine. The
increased operating range is particularly advantageous during
startup (e.g., transition from natural gas to syngas), periods of
low demand, or downtime of the gasifiers.
[0023] Turning now to the drawings, FIG. 1 is a diagram of an
embodiment of an IGCC system 100 that produces and burns syngas. As
discussed in detail below, the IGCC system 100 may include an
embodiment of a gas turbine engine fuel controller that maintains
the FNPR in a suitable range of FNPR values, thereby preventing
flashback or flame holding. Other elements of the IGCC system 100
may include a fuel source 102, which may be a solid or a liquid,
that may be utilized as a source of energy for the IGCC system. The
fuel source 102 may include coal, petroleum coke, oil, biomass,
wood-based materials, agricultural wastes, tars, coke oven gas and
asphalt, or other carbon containing items.
[0024] The fuel of the fuel source 102 may be passed to a feedstock
preparation unit 104. The feedstock preparation unit 104 may, for
example, resize or reshape the fuel source 102 by chopping,
milling, shredding, pulverizing, briquetting, or palletizing the
fuel source 102 to generate feedstock. Additionally, water, or
other suitable liquids may be added to the fuel source 102 in the
feedstock preparation unit 104 to create slurry feedstock. In other
embodiments, no liquid is added to the fuel source, thus yielding
dry feedstock. In further embodiments, the feedstock preparation
unit 104 may be omitted if the fuel source 102 is a liquid.
[0025] The feedstock may be passed to a gasifier 106 from the
feedstock preparation unit 104. The gasifier 106 may convert the
feedstock into a syngas, e.g., a combination of carbon monoxide
(CO) and hydrogen. This conversion may be accomplished by
subjecting the feedstock to a controlled amount of steam and oxygen
at elevated pressures, e.g., from approximately 20 bar to 85 bar,
and temperatures, e.g., approximately 700 degrees C. to 1600
degrees C., depending on the type of gasifier 106 utilized. The
gasification process may include the feedstock undergoing a
pyrolysis process, whereby the feedstock is heated. Temperatures
inside the gasifier 106 may range from approximately 150 degrees C.
to 700 degrees C. during the pyrolysis process, depending on the
fuel source 102 utilized to generate the feedstock. The heating of
the feedstock during the pyrolysis process may generate a solid
(e.g., char) and residue gases (e.g., CO, hydrogen, and nitrogen).
The char remaining from the feedstock from the pyrolysis process
may only weigh up to approximately 30% of the weight of the
original feedstock.
[0026] The volatiles generated during the pyrolysis process, also
known as devolatilization, may be partially combusted by
introducing oxygen to the gasifier 106. The volatiles may react
with the oxygen to form CO.sub.2 and CO in combustion reactions,
which provide heat for the subsequent gasification reactions. The
temperatures generated by the combustion reactions may range from
approximately 700 degrees C. to 1600 degrees C. Next, steam may be
introduced into the gasifier 106 during a gasification step. The
char may react with the CO.sub.2 and steam to produce CO and
hydrogen at temperatures ranging from approximately 800 degrees C.
to 1100 degrees C. In essence, the gasifier utilizes steam and
oxygen to allow some of the feedstock to be "burned" to produce CO
and release energy, which drives a second reaction that converts
further feedstock to hydrogen and additional CO.sub.2.
[0027] In this way, the gasifier 106 manufactures a resultant gas.
This resultant gas may include approximately 85% of CO and hydrogen
in equal proportions, as well as CH.sub.4, HCl, HF, COS, NH.sub.3,
HCN, and H.sub.2S (based on the sulfur content of the feedstock).
This resultant gas may be termed untreated syngas, because it
includes, for example, H.sub.2S. The gasifier 106 may also generate
waste, such as slag 108, which may be a wet ash material. This slag
108 may be removed from the gasifier 106 and disposed of, for
example, as road base or as another building material. To clean the
untreated syngas, a gas purifier 110 may be utilized. In one
embodiment, the gas purifier 110 may be a water gas shift reactor.
The gas purifier 110 may scrub the untreated syngas to remove the
HCl, HF, COS, HCN, and H.sub.2S from the untreated syngas, which
may include separation of sulfur 111 in a sulfur processor 112.
Furthermore, the gas purifier 110 may separate salts 113 from the
untreated syngas via a water treatment unit 114 that may utilize
water purification techniques to generate usable salts 113 from the
untreated syngas. Subsequently, the gas from the gas purifier 110
may include treated syngas (e.g., the sulfur 111 has been removed
from the syngas), with trace amounts of other chemicals, e.g.,
NH.sub.3 (ammonia) and CH.sub.4 (methane).
[0028] In some embodiments, a gas processor may be utilized to
remove additional residual gas components, such as ammonia and
methane, as well as methanol or any residual chemicals from the
treated syngas. However, removal of residual gas components from
the treated syngas is optional, because the treated syngas may be
utilized as a fuel even when it includes the residual gas
components, e.g., tail gas. At this point, the treated syngas may
include approximately 3% CO, approximately 55% H.sub.2, and
approximately 40% CO.sub.2 and is substantially stripped of
H.sub.2S.
[0029] In some embodiments, a carbon capture system 116 may remove
and process the carbonaceous gas (e.g., carbon dioxide that is
approximately 80-100 or 90-100% pure by volume) included in the
syngas. The carbon capture system 116 also may include a
compressor, a purifier, a pipeline that supplies CO.sub.2 for
sequestration or enhanced oil recovery, a CO.sub.2 storage tank, or
any combination thereof. The captured carbon dioxide may be
transferred to a carbon dioxide expander, which decreases the
temperature of the carbon dioxide (e.g., approximately 5-100
degrees C., or about 20-30 degrees C.), thus enabling the carbon
dioxide to be used as a suitable cooling agent for the system. The
cooled carbon dioxide (e.g., approximately 20-40 degrees C., or
about 30 degrees C.) may be circulated through the system to meet
its refrigeration needs or expanded through subsequent stages for
even lower temperatures. The treated syngas, which has undergone
the removal of its sulfur containing components and a large
fraction of its carbon dioxide, may be then transmitted to a
combustor 120, e.g., a combustion chamber, of a gas turbine engine
118 as combustible fuel.
[0030] The IGCC system 100 may further include an air separation
unit (ASU) 122. The ASU 122 may operate to separate air into
component gases by, for example, distillation techniques. The ASU
122 may separate oxygen from the air supplied to it from a
supplemental air compressor 123, and the ASU 122 may transfer the
separated oxygen to the gasifier 106. Additionally, the ASU 122 may
transmit separated nitrogen to a diluent nitrogen (DGAN) compressor
124.
[0031] The DGAN compressor 124 may compress the nitrogen received
from the ASU 122 at least to pressure levels equal to those in the
combustor 120, so as not to interfere with the proper combustion of
the syngas. Thus, once the DGAN compressor 124 has adequately
compressed the nitrogen to a proper level, the DGAN compressor 124
may transmit the compressed nitrogen to the combustor 120 of the
gas turbine engine 118. The nitrogen may be used as a diluent to
facilitate control of emissions, for example.
[0032] As described previously, the compressed nitrogen may be
transmitted from the DGAN compressor 124 to the combustor 120 of
the gas turbine engine 118. The gas turbine engine 118 may include
a turbine 130, a drive shaft 131, and a compressor 132, as well as
the combustor 120. The combustor 120 may receive fuel, such as
syngas, which may be injected under pressure from fuel nozzles.
This fuel may be mixed with compressed air as well as compressed
nitrogen from the DGAN compressor 124, and combusted within
combustor 120. As described in detail below, the gas turbine engine
fuel controller may adjust flow rates of the fuel, compressed air,
and/or compressed nitrogen to maintain the FNPR between certain
values, thereby preventing flashback or flame holding. Combustion
of the fuel may create hot pressurized exhaust gases.
[0033] The combustor 120 may direct the exhaust gases towards an
exhaust outlet of the turbine 130. As the exhaust gases from the
combustor 120 pass through the turbine 130, the exhaust gases force
turbine blades in the turbine 130 to rotate the drive shaft 131
along an axis of the gas turbine engine 118. As illustrated, the
drive shaft 131 is connected to various components of the gas
turbine engine 118, including the compressor 132.
[0034] The drive shaft 131 may connect the turbine 130 to the
compressor 132 to form a rotor. The compressor 132 may include
blades coupled to the drive shaft 131. Thus, rotation of turbine
blades in the turbine 130 may cause the drive shaft 131 connecting
the turbine 130 to the compressor 132 to rotate blades within the
compressor 132. This rotation of blades in the compressor 132
causes the compressor 132 to compress air received via an air
intake in the compressor 132. The compressed air may then be fed to
the combustor 120 and mixed with fuel and compressed nitrogen to
allow for higher efficiency combustion. The drive shaft 131 may
also be connected to load 134, which may be a stationary load, such
as an electrical generator for producing electrical power, for
example, in a power plant. Indeed, load 134 may be any suitable
device that is powered by the rotational output of the gas turbine
engine 118.
[0035] The IGCC system 100 also may include a steam turbine engine
136 and a heat recovery steam generation (HRSG) system 138. The
steam turbine engine 136 may drive a second load 140. The second
load 140 may also be an electrical generator for generating
electrical power. However, both the first 130 and second 140 loads
may be other types of loads capable of being driven by the gas
turbine engine 118 and steam turbine engine 136. In addition,
although the gas turbine engine 118 and steam turbine engine 136
may drive separate loads 134 and 140, as shown in the illustrated
embodiment, the gas turbine engine 118 and steam turbine engine 136
may also be utilized in tandem to drive a single load via a single
shaft. The specific configuration of the steam turbine engine 136,
as well as the gas turbine engine 118, may be
implementation-specific and may include any combination of
sections.
[0036] The system 100 may also include the HRSG 138. Heated exhaust
gas from the gas turbine engine 118 may be transported into the
HRSG 138 and used to heat water and produce steam used to power the
steam turbine engine 136. Exhaust from, for example, a low-pressure
section of the steam turbine engine 136 may be directed into a
condenser 142. The condenser 142 may utilize a cooling tower 128 to
exchange heated water for chilled water. The cooling tower 128 acts
to provide cool water to the condenser 142 to aid in condensing the
steam transmitted to the condenser 142 from the steam turbine
engine 136. Condensate from the condenser 142 may, in turn, be
directed into the HRSG 138. Again, exhaust from the gas turbine
engine 118 may also be directed into the HRSG 138 to heat the water
from the condenser 142 and produce steam.
[0037] In combined cycle systems, such as the IGCC system 100, hot
exhaust may flow from the gas turbine engine 118 and pass to the
HRSG 138, where it may be used to generate high-pressure,
high-temperature steam. The steam produced by the HRSG 138 may then
be passed through the steam turbine engine 136 for power
generation. In addition, the produced steam may also be supplied to
any other processes where steam may be used, such as to the
gasifier 106. The gas turbine engine 118 generation cycle is often
referred to as the "topping cycle," whereas the steam turbine
engine 136 generation cycle is often referred to as the "bottoming
cycle." By combining these two cycles as illustrated in FIG. 1, the
IGCC system 100 may lead to greater efficiencies in both cycles. In
particular, exhaust heat from the topping cycle may be captured and
used to generate steam for use in the bottoming cycle.
[0038] FIG. 2 is a block diagram of a gas turbine engine 118 that
may include an exemplary fuel control system configured to expand
an operational range of the gas turbine engine 118 by adding a
diluent to a fuel to maintain a suitable FNPR, thereby preventing
flashback and flame holding. Not only may the gas turbine engine
118 be used in the IGCC system 100 described above, but in certain
embodiments, the gas turbine engine 118 may be used in aircraft,
watercraft, locomotives, power generation systems, or combinations
thereof. The illustrated gas turbine engine 118 includes an air
intake section 160, the compressor 132, a combustor section 166,
the turbine 130, and an exhaust section 162. The turbine 130 is
coupled to the compressor 132 via the drive shaft 131.
[0039] As indicated by the arrows, air may enter the gas turbine
engine 118 through the intake section 160 and flow into the
compressor 132, which compresses the air prior to entry into the
combustor section 166, also referred to as the combustion system.
The illustrated combustor section 166 includes a combustor housing
164 disposed concentrically or annularly about the drive shaft 131
between the compressor 132 and the turbine 130. The compressed air
from the compressor 132 enters one or more combustors 120 where the
compressed air may mix and combust with fuel within the combustors
120 to drive the turbine 130. From the combustor section 166, the
hot combustion gases flow through the turbine 130, driving the
compressor 132 via the drive shaft 131. For example, the combustion
gases may apply motive forces to turbine rotor blades within the
turbine 130 to rotate the drive shaft 131. After flowing through
the turbine 130, the hot combustion gases may exit the gas turbine
engine 118 through the exhaust section 162.
[0040] The gas turbine engine 118 may use one or more fuels. For
example, the gas turbine engine 118 may be configured to burn a
first fuel 168, which may include, but is not limited to, natural
gas, distillate, liquefied petroleum gas (LPG), or a combination
thereof. A first fuel control valve 170 may adjust the flow rate of
the first fuel 168. However, other flow adjusting or flow
controlling devices may be used instead of the control valves shown
in FIG. 2. In addition, the gas turbine engine 118 may be
configured to burn a second fuel 172, which may include, but is not
limited to, syngas. As described above, syngas may be produced by
one or more gasifiers of the IGCC system 100. A second fuel control
valve 174 may adjust the flow rate of the second fuel 172. Finally,
a diluent 176 may be injected into the gas turbine engine 118. As
described above, examples of the diluent 176 include, but are not
limited to, nitrogen, carbon dioxide, steam, water vapor, or
combinations thereof. A diluent control valve 178 may adjust the
flow rate of the diluent 176. The first fuel 168, the second fuel
172, and the diluent 176 may be directed to the combustor 120 via
injection line 180. Although the injection line 180 is shown as a
single line, separate lines may be used for each of the first fuel
168, the second fuel 172, and/or the diluent 176. Alternatively,
the diluent 176 may be blended with either the first fuel 168 or
the second fuel 172 prior to injection into the combustor 120. In
addition, although shown as flowing directly to the combustor 120,
the injection line 180 may be directed to one or more fuel nozzles
disposed in the head end of the combustor 120.
[0041] In the illustrated embodiment, a fuel control system 182, or
fuel controller, is shown schematically between the combustor 120
and the first and second fuels 168 and 172, and the diluent 176.
The fuel control system 182 may receive one or more signals, or
feedback, from various sensors disposed throughout the gas turbine
engine 118 to increase an operational range of the gas turbine
engine 118 via control of the diluent 176, thereby preventing
flashback and flame holding. For example, an intake section sensor
184 may send a signal to the fuel control system 182. Examples of
parameters measured by the intake section sensor 184 include, but
are not limited to, intake temperature, intake pressure, intake
flow rate, intake humidity, or combinations thereof. Next, a
compressor sensor 186 may send a signal to the fuel control system
182. Examples of parameters measured by the compressor sensor 186
include, but are not limited to, compressor temperature, compressor
pressure, inlet guide vane (IGV) position, or combinations thereof
at one or more compressor stages. A combustor sensor 188 may send
signals indicative of parameters in the combustor section 166 to
the fuel control system 182. Examples of parameters measured by the
combustor sensor 188 include, but are not limited to, FNPR,
combustor temperature, combustor pressure, combustion gas
composition, combustion dynamics, flame characteristics, or
combinations thereof. Next, a turbine sensor 192 may be used to
measure parameters in the turbine 130 and to send signals to the
fuel control system 182. Examples of parameters measured by the
turbine sensor 192 include, but are not limited to, turbine
temperature, turbine pressure, turbine speed, turbine vibration, or
combinations thereof at one or more turbine stages. Finally, an
exhaust sensor 194 may be used to send signals to the fuel control
system 182. Examples of parameters measured by the exhaust sensor
194 include, but are not limited to, exhaust temperature, exhaust
pressure, exhaust gas composition (e.g., emissions), speed of the
drive shaft 131, corrected speed, or combinations thereof.
[0042] In response to the signals 198 received from the various
sensors of the gas turbine engine 118, the fuel control system 182
may send signals 196 to the first fuel control valve 170, the
second fuel control valve 174, and/or the diluent control valve 178
to control the FNPR (or other parameters) to expand the operational
range of the gas turbine engine 118. For example, the fuel control
system 182 may receive signals 198 indicating that additional
diluent 176 is needed to increase the FNPR above the minimum FNPR,
and/or less diluent 176 is needed to reduce the FNPR below the
maximum FNPR. If the FNPR is low, then the fuel control system 182
may send signals 196 to open the diluent control valve 178 and/or
partially close the first and second fuel control valves 170 and
174. In addition to the parameters discussed above, other sensors
disposed within the gas turbine engine 118 or in adjacent equipment
may indicate parameters that may be used by the fuel control system
182. Examples of other parameters include, but are not limited to,
heating values, load status, fuel pressure, fuel flow rate, diluent
pressure, diluent flow rate, or combinations thereof. Examples of
specific control schemes used by the fuel control system 182 are
described in more detail below.
[0043] FIG. 3 shows a graph 210 of an embodiment of an operating
envelope of a gas turbine engine, illustrating an operational
expansion using the fuel control system 182 to adjust diluent and
thus FNPR. An x-axis 212 indicates the ratio of the first fuel to
the second fuel, which may be referred to as a co-fire ratio. In
the graph 210, the first fuel is natural gas and the second fuel is
syngas. On the left end of the x-axis 212, the co-fire ratio
represents 100% natural gas and 0% syngas. Accordingly, on the
right end of the x-axis 212, the co-fire ratio represents 0%
natural gas and 100% syngas. A y-axis 214 indicates a load of the
gas turbine engine. Specifically, the lower end of the y-axis 214
represents 0% load and the upper end of the y-axis 214 represents a
maximum load of 100%.
[0044] In the graph 210, a natural gas control valve minimum stroke
curve 216 represents an upper boundary of the operating envelope of
the gas turbine engine. A stroke of the control valve may refer to
a position of a trim, stem, plug, ball, or similar device, inside
the control valve, which is capable of varying the flow rate
through the control valve. For example, at a stroke of 0%, little
or no flow may pass through the control valve. Correspondingly, at
a stroke of 100%, the flow rate may approach a maximum for the
control valve. In addition, the control valve may have a minimum
stroke below which controlling the flow rate is not recommended
because control may become erratic. In other words, the flow rate
is not controlled below the minimum stroke and instead, the valve
is closed by reducing the stroke to 0%. The minimum stroke may be a
function of a pressure drop across the control valve and/or the
flow rate passing through the control valve. For example, at high
flow rates, the minimum stroke of the natural gas control valve may
be close to 0%. However, as the flow rate decreases, the minimum
stroke may increase.
[0045] With the preceding in mind and returning to the graph 210,
the natural gas minimum stroke curve 216 gradually slopes down and
to the left as the load decreases. For example, at a load of
approximately 100%, the corresponding co-fire ratio along the
natural gas curve 216 is approximately 10% natural gas and 90%
syngas. In other words, if the load is approximately 100%, the
minimum stroke of the natural gas control valve is low enough to
enable good control of the valve down to a flow rate corresponding
to a co-fire ratio of approximately 10% natural gas and 90% syngas.
In contrast, at a load of approximately 15%, represented by line
226, the corresponding co-fire ratio along the natural gas curve
216 is approximately 60% natural gas and 40% syngas. In other
words, if the load is approximately 15%, the minimum stroke of the
natural gas control valve is greater, such that good control of the
valve is enabled only to a flow rate corresponding to a co-fire
ratio of approximately 60% natural gas and 40% syngas. Thus,
operation with less than approximately 60% natural gas may be
desired at a load of approximately 15%, but may not possible
because of the minimum stroke of the natural gas control valve.
More generally, operation of the gas turbine engine at lower loads
may be limited to higher percentages of natural gas and lower
percentages of syngas than may be desired.
[0046] In the graph 210, a minimum FNPR curve 218 represents a
lower boundary of the operating envelope of the gas turbine engine.
The FNPR increases as the heating value of the fuel decreases.
Syngas has a higher concentration of hydrogen than natural gas,
which means that the heating value of syngas is lower than that of
natural gas. For example, syngas may have a heating value that is 3
times, 4 times, 5, times, 6 times, 7 times, or 8 times lower than
that of natural gas. Thus, the minimum FNPR curve 218 slopes down
and to the right as the load decreases. For example, at a load of
approximately 100%, the corresponding co-fire ratio along the
minimum FNPR curve 218 is approximately 55% natural gas and 45%
syngas. In other words, if the load is approximately 100%, the
minimum FNPR may be maintained if at least approximately 45% syngas
is fed to the gas turbine engine. In contrast, at a load of
approximately 15%, the corresponding co-fire ratio along the
minimum FNPR curve 218 is approximately 25% natural gas and 75%
syngas. In other words, if the load is approximately 15%, the
minimum FNPR is greater, such that more syngas, namely at least
approximately 75%, is fed to maintain operation of the gas turbine
engine above the minimum FNPR. Thus, for example, operation with
less than approximately 75% syngas may be desired at a load of
approximately 15%, but may not possible because the minimum FNPR
cannot be maintained. More generally, operation of the gas turbine
engine at lower loads may be limited to lower percentages of
natural gas and higher percentages of syngas than may be
desired.
[0047] In addition, a minimum load of approximately 30%,
represented by line 220, may serve as a third boundary for the
operating envelope of the gas turbine engine. Although the gas
turbine engine may operate in a small area of the operating
envelope below 30% load and between natural gas and minimum FNPR
curves 216 and 218, 30% may be selected as a convenient minimum to
help prevent the gas turbine engine from quickly exceeding the
boundaries established by natural gas and minimum FNPR curves 216
and 218 where their curvatures increase. Thus, the natural gas
control valve minimum stroke curve 216, the minimum FNPR curve 218,
and the minimum load of 30% curve 220 may define an operating
region 222.
[0048] Also shown in FIG. 3 near the left side of the graph 210 is
a syngas control valve minimum stroke curve 224. As with the
natural gas control valve, control of the syngas control valve may
become erratic below a minimum stroke. For example, near a load of
approximately 100%, the corresponding co-fire ratio along the
syngas curve 224 is approximately 90% natural gas and 10% syngas.
As the load decreases, the syngas curve 224 slopes to the right,
such that at a load of approximately 15%, the corresponding co-fire
ratio along the syngas curve 224 may be approximately 60% natural
gas and 40% syngas. Thus, without the minimum FNPR curve 218, the
syngas control valve minimum stroke curve 224 would represent the
lower boundary for the operating envelope of the gas turbine
engine.
[0049] Accordingly, in various embodiments described below, diluent
may be added to the fuel stream to the gas turbine engine to avoid
the minimum FNPR curve 218 as the lower boundary for the operating
envelope of the gas turbine engine. Specifically, the heating value
of the diluent may be low. Thus, by adding diluent to the fuel, the
heating value of the mixture is decreased, which increases the
FNPR. In certain embodiments, by increasing the FNPR, operation
above the minimum FNPR may be maintained, while at the same time
decreasing the amount of syngas fed to the gas turbine engine.
Thus, the minimum load of the gas turbine engine may shift from
approximately 30%, represented by line 220, to approximately 15%,
represented by line 226 enabling the gas turbine engine to operate
at a lower load. In other words, the operating envelope of the gas
turbine engine, operating with diluent added to the fuel, may
include not only operating region 222, but also operating region
228, which results because the syngas control valve minimum stroke
curve 224 represents the new lower boundary. For example, the range
of co-fire ratios of the gas turbine engine at approximately 100%
load may increase from a range of approximately 45% syngas and 55%
natural gas to 90% syngas and 10% natural gas to a new range of
approximately 10% syngas and 90% natural gas to 90% syngas and 10%
natural gas. The range of co-fire ratios increases for all loads
between the new minimum load of 15% and the maximum load of
100%.
[0050] The increased range of co-fire ratios of the gas turbine
engine may be advantageous during startup and/or shutdown
situations. For example, during startup of the IGCC plant 100 and
gas turbine engine 118, syngas may not be immediately available in
desired quantities because one or more gasifiers 106 may be
offline. Without adding diluent to the fuel, startup of the gas
turbine engine 118 may be delayed until sufficient syngas is
available for the gas turbine engine 118 to operate near the
co-fire ratio of approximately 45% syngas and 55% natural gas.
However, according to particular embodiments, the fuel controller
may increase the flow of diluent and decrease the flow of syngas so
that the co-fire ratio changes to approximately 10% syngas and 90%
natural gas. Thus, the gas turbine engine 118 may be started when
less syngas is available, which may enable the gas turbine engine
118 to be started sooner during the startup of the IGCC plant 100.
Specifically, the gas turbine engine 118 may be started up
approximately 1 hour, 2 hours, 3 hours, or 5 hours sooner when
diluent is added to the fuel according to an embodiment. Thus, the
amount of flaring to meet emission permit limits during startup may
be reduced. Flaring refers to the burning of gases from an elevated
stack. As syngas becomes more available during startup, the fuel
controller may control a fuel transition from natural gas to syngas
to maintain operation above the minimum FNPR. Correspondingly, the
fuel controller may control the fuel transition from syngas to
natural gas as syngas becomes less available during shutdown of the
combustion system to maintain operation above the minimum FNPR.
Thus, the increased range of co-fire ratios may be advantageous
during startup (e.g., transition from natural gas to syngas),
periods of low demand, or maintenance or downtime of one or more of
the gasifiers of the IGCC plant 100.
[0051] FIG. 4 is a block diagram of an embodiment of a fuel control
system 240 that may be used to achieve the increased operating
envelope and help prevent flashback and flame holding as discussed
above. Elements in common with those shown in FIG. 2 are labeled
with the same reference numerals. In the illustrated embodiment,
the diluent 176 is blended with the second fuel 172 prior to
injection in the gas turbine engine. Specifically, a diluent line
242 may join with a second fuel line 244 to mix the diluent 176
with the second fuel 172. The mixture of the diluent 176 and the
second fuel 172 is directed to the gas turbine engine through a
diluent and second fuel mixture line 246. Disposed on the diluent
and second fuel mixture line 246 may be a LHV sensor 248, such as,
but not limited to, a calorimeter. A first fuel line 250 carries
the first fuel 168 to the gas turbine engine. The fuel control
system 182 may adjust the flow rates of the first fuel 168, the
second fuel 172, and/or the diluent 176 flowing to combustor fuel
nozzles 252. The line 180 carrying the first fuel 168, the second
fuel 172, and the diluent 176 to the combustor fuel nozzles 252 may
consist of one or more lines.
[0052] In block 254 of FIG. 4, the FNPR is measured or calculated.
Using the FNPR from block 254 and the signal 198 representing the
LHV as measured by LHV sensor 248, the LHV setpoint or the diluent
flow rate is adjusted in block 256. As discussed above, the FNPR
increases as the LHV decreases. Again, the diluent may include a
vapor or gas, such as a noble gas or non-combustible gas or vapor.
Examples include steam, nitrogen, carbon dioxide, or combinations
thereof. Thus, by adding diluent to the fuel, the LHV decreases and
the FNPR increases. For example, if the FNPR from block 254
decreases, block 256 may send signal 196 to the diluent control
valve 178 to increase the diluent flow rate. Likewise, if the LHV,
as measured by LHV sensor 248, increases, block 256 may send signal
196 to the diluent control valve 178 to increase the flow rate of
the diluent 176. Specific embodiments of fuel control systems 182
are discussed in more detail below.
[0053] For example, FIG. 5 shows an embodiment of a fuel control
system 270 using schedule-based, or open-loop, control. Elements in
common with those shown in FIG. 4 are labeled with the same
reference numerals. A diluent flow meter 272 measures the flow rate
of the diluent 176. Other aspects of the first fuel 168, second
fuel 172, and diluent 176 are similar to that described above.
Block 274 represents the values of operating parameters obtained
from sensors throughout the gas turbine engine. Examples of
measured operating parameters include, but are not limited to,
inlet guide vane (IGV) position, corrected speed, exhaust
temperature, fuel flow rate, fuel LHV, or combinations thereof. In
block 276, a diluent flow rate is identified using a schedule and
based on the measured operating parameters from block 274. The
schedule of block 276 may be included in control software and/or
memory of the fuel control system 182. In addition, the schedule is
established to maintain the minimum FNPR across all anticipated
operating conditions, thereby preventing flashback and flame
holding. For example, a theoretical schedule may be developed and
then verified and adjusted in the field based on temporary FNPR
measurements. Block 278 represents the diluent flow rate setpoint
selected using the schedule of block 276. In addition, block 280
represents the measured diluent flow rate based on the signal 198
from the diluent flow meter 272.
[0054] In decision block 282 of FIG. 5, the difference between the
measured diluent flow rate from block 280 and the diluent flow
setpoint from block 278 is determined. If the difference is less
than an allowable value, then in block 284, the setpoint for the
diluent control valve 178 is maintained. In other words, the
diluent flow rate is maintained near the current measured diluent
flow rate. Thus, the allowable value represents a range that the
measured diluent flow rate may deviate from the diluent flow
setpoint. On the other hand, if the difference between the measured
diluent flow rate and the diluent flow rate setpoint is greater
than the allowable value, then in block 286, the setpoint for the
diluent control valve 178 is adjusted. For example, if the measured
diluent flow rate is greater than the diluent flow rate setpoint,
then the setpoint for the diluent control valve 178 is decreased.
On the other hand, if the measured diluent flow rate is less than
the diluent flow rate setpoint, then the diluent flow rate setpoint
to the diluent control valve 178 is increased. By maintaining the
diluent flow rate at or near the diluent flow rate setpoint, the
fuel control system 182 may maintain the FNPR above the minimum
FNPR and increase the operability envelope of the gas turbine
engine as described above. Furthermore, schedule-based control may
be useful when the gas turbine engine operates at certain defined
operating points.
[0055] FIG. 6 shows an embodiment of a fuel control system 300
using a transfer function for closed-loop control. Elements in
common with those shown in FIG. 5 are labeled with the same
reference numerals. As with the schedule-based control shown in
FIG. 5, block 274 represents measured operating parameters of the
gas turbine engine. In block 302, the FNPR is calculated based on a
transfer function built into the control software stored on memory.
The transfer function may be a mathematical representation of a
relationship between input and output of a system. For example, the
transfer function may be derived using a Laplace transform. In
decision block 304, the calculated FNPR is compared with a low-low
FNPR value. The low-low FNPR value is less than a low FNPR value
that may result in an alarm. If the calculated FNPR is less than
the low-low FNPR value, then in block 306, the fuel to the gas
turbine engine is transferred, or transitioned, from the second
fuel 172 to the first fuel 168, which may be natural gas,
distillate, LPG, or a combination thereof, in certain embodiments.
The first fuel 168 may also be referred to as a backup fuel or
startup fuel. As described above, the primary nozzle may be used
for the first fuel 168 and the secondary nozzle may be used for the
second fuel 172. The nozzle area of the primary nozzle may be much
less than that of the secondary nozzle. Thus, the pressure drop
across the primary nozzle is much higher than that of the secondary
nozzle, which may cause the FNPR to increase. This increase in the
FNPR may be much larger than the decrease in FNPR caused by the
transition to the first fuel 168 with a higher heating value than
the second fuel 172. Thus, by switching to the first fuel 168, the
calculated FNPR may increase above the low-low FNPR value. If for
some reason, the calculated FNPR falls below a low-low-low FNPR
value, then the gas turbine engine is shut down. The low-low-low
FNPR value is less than the low-low FNPR value.
[0056] Returning to decision block 304, if the calculated FNPR is
greater than the low-low FNPR level, then the calculated FNPR is
compared with a low FNPR level in decision block 308. If the
calculated FNPR is greater than the low FNPR level, then in block
310 the LHV setpoint is maintained. In other words, the flow rate
of the diluent 176 is maintained at the current flow rate. On the
other hand, if the calculated FNPR is less than the low FNPR level,
then in block 312, the LHV setpoint is decreased by sending a
signal 196 to the diluent control valve 178. Next, in decision
block 314, the difference between the LHV and the LHV setpoint is
calculated. If the difference is less than an allowable value, then
in block 316, the setpoint for the diluent control valve 178 is
maintained. However, if the difference between the LHV and the LHV
setpoint is greater than the allowable value, then in block 318,
the setpoint of the diluent control valve 178 is adjusted. For
example, if the measured LHV based on LHV sensor 248 is less than
the LHV setpoint, then the flow rate of the diluent 176 is
increased. On the other hand, if the LHV is greater than the LHV
setpoint, then the flow rate of the diluent 176 is decreased. Thus,
the fuel control system 182 may maintain the FNPR above the minimum
FNPR and increase the operability envelope of the gas turbine
engine and help prevent flashback and flame holding as described
above. Furthermore, using the transfer function may be useful when
the effect of a few operating parameters on the FNPR can be
identified and defined.
[0057] FIG. 7 shows an embodiment of a fuel control system 330
using a model for closed-loop control. Elements in common with
those shown in FIG. 6 are labeled with the same reference numerals.
Block 274 represents measured operating parameters of the gas
turbine engine, such as those described above. In block 332, a real
time gas turbine engine model predicts the FNPR. For example, one
type of model-based control is model predictive control (MPC),
which is an advanced method of process control that relies on
dynamic models of the process, most often linear empirical models
obtained by system identification. Using these dynamic models, the
fuel control system 182 can predict future values of the FNPR and
take appropriate action to maintain the FNPR within a defined
range. In decision block 334, the predicted FNPR is compared with a
low-low FNPR value, which is less than a low FNPR value that may
result in an alarm. If the predicted FNPR is less than the low-low
FNPR value, then in block 306, operation of the gas turbine engine
is transitioned to the first fuel 168. If the predicted FNPR falls
below a low-low-low FNPR value, which is less than the low-low FNPR
value, then the gas turbine engine is shut down.
[0058] Returning to decision block 334, if the predicted FNPR is
greater than the low-low FNPR value, then the predicted FNPR is
compared with a low FNPR level in decision block 336. If the
predicted FNPR is greater than the low FNPR, then in block 310, the
LHV setpoint is maintained. On the other hand, if the predicted
FNPR is less than the low FNPR, then in block 312, the LHV setpoint
is decreased. In decision block 314, the difference between the LHV
and the LHV setpoint is calculated and compared with an allowable
value. If the difference is less than the allowable value, then in
block 316, the setpoint for the diluent control valve 178 is
maintained. On the other hand, if the difference between the LHV
and the LHV setpoint is greater than the allowable value, then in
block 318, the setpoint of the diluent control valve 178 is
adjusted. Other aspects of the model-based control shown in FIG. 7
are similar to that of the transfer function based closed-loop
control shown in FIG. 6. In addition, other methods of process
control other than those described above may be used to control the
flow rate of diluent 176 to maintain the FNPR above the minimum
FNPR. Examples of other technologies that may be used for the fuel
control system 182 include, but are not limited to, linear or
non-linear controllers, programmable logic controllers, distributed
control systems, statistical process controllers, or other methods
of process control.
[0059] This written description uses examples to disclose the
invention, including the best mode, and also to enable any person
skilled in the art to practice the invention, including making and
using any devices or systems and performing any incorporated
methods. The patentable scope of the invention is defined by the
claims, and may include other examples that occur to those skilled
in the art. Such other examples are intended to be within the scope
of the claims if they have structural elements that do not differ
from the literal language of the claims, or if they include
equivalent structural elements with insubstantial differences from
the literal language of the claims.
* * * * *